1. Field of the Invention
This invention relates in general to oil well electrical submersible pumps. In particular aspects, the invention relates to the use of coiled tubing-disposed pumps for continuing production after a production tubing-disposed pump has failed.
2. Related Art
Electrical submersible pumps (xe2x80x9cESPsxe2x80x9d) are commonly used in oil and gas wells for producing large volumes of well fluid after natural production has decreased in flow. In conventional methods of production, an ESP would be installed by incorporating it within a string of production tubing or conventional threaded pipe and then lowering the ESP assembly into the well. This process employs the use of a rig and is time consuming. A few ESPs have been installed on coiled tubing for pumping up the annulus surrounding the coiled tubing. Coiled tubing is deployed by a coiled tubing injector from a large reel. There is no need for a rig, and the running time is generally less than for an ESP installed on production tubing. However, because standard wellheads are not designed to receive coiled tubing without first removing the production string, these systems provide no real advantages over traditional systems.
Unfortunately, most ESPs only have a 2 to 3 year life. Thus, at some point in time, a new ESP is needed to continue producing the well. The conventional method to deploy the new ESP is to use a workover rig to remove the production string from the well and replace the worn-out ESP that is incorporated in the string with a new one. The process of removal and replacement costs the well operator both time and money, particularly for offshore subsea wells. Proposals have been made to use a Y-tool with one leg supporting a main ESP and the other a back-up ESP. Improvements to the methods and systems of the prior art are desirable.
This invention provides systems and methods for staged production from a wellbore. In exemplary embodiments described herein, there may be three progressive stages to the production process. The first stage may be natural production, which uses natural formation pressures to bring the production fluid to the surface. The second stage of production is through the use of a first fluid pump, which may be installed at the time of original well completion on conventional threaded pipe. The third stage is the deployment and use of a second fluid pump on coiled tubing within the production tubing for additional production.
Exemplary production systems are described that allow a well to be progressively produced without the need to remove production tubing from the wellbore. The exemplary systems include a Y-tool with two legs. The Y-tool is suspended at the lower end of a string of production tubing. One of the legs supports a first fluid pump. In one preferred embodiment, there is a diverter assembly incorporated into the Y-tool for selectively isolating flow through either of the legs thereby allowing selective use of the first fluid pump. In an alternative embodiment, a sliding sleeve arrangement provides selective flow through the first fluid pump.
At the point where natural pressure or flow decreases in the reservoir, the first, production tubing-based pump is turned on and operated to failure. Upon failure of the production tubing-based pump, a second fluid pump is run into the production tubing on coiled tubing. Additionally production fluid to the surface is flowed using the second pump, thereby eliminating the need to remove the production tubing from the wellbore and then replace the first fluid pump. Upon failure of the coiled tubing-based pump, that pump may be easily removed from the wellbore and replaced without the cost and time associated with removal of the production tubing from the wellbore.